When drilling for oil and gas, the downhole drill bit is connected to surface equipment by way of a drill string. The drill string is hollow whereby drilling fluid or mud can be pumped down the borehole, the mud acting to lubricate the drill bit and to carry drill cuttings back to the surface. The mud and entrained drill cuttings return to the surface along the outside of the drill string, the drill string being smaller than the diameter of the borehole.
In some drilling applications the drill string is rotated at the surface, with the rotation being communicated to the drill bit by the drill string. In other drilling applications a downhole motor such as a mud motor is provided, which uses the flowing mud to drive the drill bit to rotate. A downhole motor may be used with a rotating, or a non-rotating, drill string.
The surface equipment applies a downhole force upon the drill string, which force is communicated to the drill bit. In addition to the torque seeking to rotate the drill bit there is also a force acting to advance the bit into the rock at the leading end of the borehole, the latter force typically being referred to as “weight on bit”.
The drill operator will typically seek to maximize the weight on bit so that the drill advances as quickly as possible through the rock. However, there is a maximum limit for the weight on bit which depends upon the bit design and the drilling conditions. Exceeding the maximum weight on bit for the particular bit design and drilling conditions will increase the drag upon the drill bit and cause the drill bit to slow down or stall, i.e. the drill bit will rotate more slowly, or in extreme cases stop rotating altogether.
If the drill bit does rotate more slowly than the drill string, or than the output of the downhole motor, then the drill string will be caused to twist as torque output from the surface equipment (or downhole motor) increases in response to maintain the original rate of rotation. Eventually, torque at the drill bit will exceed the resistance to rotation and the drill bit will start to rotate again.
Such a phenomenon is known as “stick-slip” and is a major concern to drill operators. Firstly, the drill string may be damaged by the requirement to twist as the drill bit slows down or stops. Secondly, the drill bit will often rotate very rapidly, and uncontrolledly, as the torque in the twisted drill string is relieved. Periods of slow or non-rotation of the drill bit followed by rapid and uncontrolled rotation of the drill bit will often be repeated if they are not countered.
Drill operators seek to avoid stick-slip by reacting to reductions in the rate of rotation of the drill bit by reducing the weight on bit, so that the drill bit resumes its desired rate of rotation quickly without undue twisting of the drill string. A reduction in the rate of rotation of the drill bit can be detected directly by measuring the rate of rotation of the drill bit, or (more typically) by measuring the torque being applied to the drill bit, the torque increasing as the rate of rotation reduces.
The prior art includes torque control devices which can automatically reduce the weight on bit if the torque upon the drill bit exceeds a certain threshold. One prior art arrangement is described in WO 2004/090278 (Tomax). This document has an outer sleeve connected to the drill string and an inner shaft connected to the drill bit. The outer sleeve and the inner shaft are interconnected by a helical thread. A spring biases the inner shaft outwardly of the outer sleeve, into engagement with a fixed stop upon the outer sleeve. During normal drilling operations the inner shaft is driven to rotate by the sleeve, and in turn drives the drill bit to rotate at the same rate as the drill string. If the drill bit slows down or stops, however, the torque upon the drill bit increases sufficiently to drive the sleeve to rotate relative to the shaft, compressing the spring. The helical thread between the inner shaft and the outer sleeve means that rotation of the inner shaft relative to the outer sleeve causes the inner shaft to retract into the sleeve, thereby retracting the drill bit and reducing the weight on bit. As the weight on bit is reduced a point is reached where the drill bit can resume its rotation. The spring causes the inner sleeve to return to its extended position in engagement with the fixed stop, during which the drill bit rotates faster than the drill string.
The Tomax arrangement can include an oil damper, i.e. the spring and cooperating helical threaded components can lie within an oil reservoir which damps out the movement of the inner shaft relative to the outer sleeve, preventing uncontrolled rotation of the inner sleeve and therefore the drill bit.
A similar arrangement is described in U.S. Pat. No. 7,044,240 (McNeilly), and also in Tomax's later U.S. Pat. No. 7,654,344, which uses a helical spring rather than a helical thread to interconnect the outer sleeve and the inner shaft.
The prior art arrangements all rely upon compression springs, and it will be understood that the force provided by those springs must exceed the weight on bit. The design of the tools must therefore include a calculation for the maximum weight on bit which can be catered for, and once the spring rate has been determined it cannot be adjusted. When drilling for oil and gas, however, the rock type through which the drill must pass can vary significantly during a drilling operation, and if the spring force is set too low the tool may reduce the drilling torque even if the drill is not sticking, i.e. the drill operator cannot exceed the weight on bit determined by the spring force, even if the drilling conditions are more favorable than expected and the drill bit would not stick with a greater weight on bit. If, on the other hand, the spring force is set too high for the particular drilling conditions, the drill bit may undergo significant stick-slip without actuation of the torque control device.